1. Field of the Invention
This invention relates to a method for recovering petroleum from subterranean petroleum-containing formations, and more particularly to a surfactant flooding method for recovering petroleum from high temperature subterranean petroleum-containing formations. Still more particularly, this invention pertains to a novel surfactant mixture which resists bacterial attack and functions effectively in high temperature formations containing water having high polyvalent ion concentrations, e.g., high calcium or magnesium concentrations, which cause precipitation of conventional surfactants, and to a method for using such novel surfactant composition in a surfactant flooding process for recovering petroleum.
2. Description of the Prior Art
Petroleum is normally recovered from subterranean formations in which it has accumulated by penetrating said formation with one or more wells and pumping or permitting the petroleum to flow to the surface through these wells. Recovery of petroleum from petroleum-containing formations is possible only if certain conditions exist. There must be an adequate amount of petroleum in the formation, and there must be sufficient porosity and permeability or interconnected flow channels throughout the formation to permit the flow of fluids therethrough if sufficient pressure is applied to the fluid. When the subterranean petroleum-containing formation has natural energy present in the form of an underlying active water drive, or gas dissolved in the petroleum which can exert sufficient pressure to drive the petroleum to the producing well, or a high pressure gas cap above the petroleum within the petroleum reservoir, this natural energy is utilized to recover petroleum. Recovery of petroleum by utilizing natural energy is referred to as primary recovery. When the natural energy source is depleted, or in the instance of those formations which do not originally contain sufficient natural energy to permit primary recovery operations, some form of supplemental recovery process must be applied to the formation to extract additional petroleum. Supplemental recovery is frequently referred to as secondary or tertiary recovery, although in fact it may be primary, secondary or tertiary in sequence of employment.
Water flooding, commonly referred to as secondary recovery, involves the injection of water into the subterranean, petroliferous formation for the purpose of displacing petroleum toward the producing well. This is the most economical and widely practiced supplemental recovery method. Water does not displace petroleum with high efficiency, however, since water and oil are immiscible, and also because the interfacial tension between water and oil is quite high. Persons skilled in the art of oil recovery have recognized this weakness of water flooding and many additives have been described in the prior art for decreasing the interfacial tension between the injected water and the formation petroleum. For example, U.S. Pat. No. 2,233,381 (1941) disclosed the use of polyglycol ether as a surface-active agent or surfactant to increase the capillary displacement efficiency of an aqueous flooding medium. U.S. Pat. No. 3,302,713 and U.S. Pat. No. 3,468,377 (1969) describe the use of petroleum sulfonates for oil recovery. Other surfactants which have been proposed for oil recovery include alkyl sulfates and alkyl or alkylaryl sulfonates.
The above described surfactants are satisfactory for surfactant flooding in petroliferous formations only if the calcium and magnesium concentration of the formation water is below about 500 parts per million. Petroleum sulfonate is a popular and desirable surfactant because of its high surface-activity and low unit cost, although it also suffers from the limitation that it can be used only when the total formation water hardness (calcium + magnesium) is less than about 500 parts per million. If the formation water calcium and/or magnesium content exceeds about 500 parts per million, petroleum sulfonates precipitate rendering them inoperative for oil recovery and in some instances causing plugging of the formation.
Many subterranean petroleum-containing formations are known to exist which contain polyvalent ions such as magnesium and calcium in concentrations far in excess of 500 parts per million. The most common of such reservoirs are limestone formations which may have polyvalent ion concentrations from 200 to as high as 20,000 parts per million in the original connate water, and the formation water, after the formation has been subjected to flooding with fresh water, may have concentrations of calcium and/or magnesium from about 500 to about 15,000 parts per million. Since many surfactants taught in the art as being usable for oil recovery operations precipitate when exposed to aqueous environments having a total hardness in excess of about 500 parts per million, such surfactants cannot be used in limestone reservoirs. If an aqueous solution of petroleum sulfonate, for example, were injected into a limestone reservoir, the petroleum sulfonate would precipitate on contacting the high calcium-containing formation water. In such a process, the flood water would have essentially no surfactant present in it to decrease the interfacial tension between water and petroleum. Furthermore, precipitated petroleum sulfonate plugs small flow channels in subterranean, petroleum-containing formations decreasing the formation porosity and injectivity, thereby causing a substantial decrease in the oil displacement efficiency.
In U.S. Pat. No. 3,508,612, J. Reisberg et al., 1970, an oil recovery method employing a mixture of sulfonates, specifically petroleum sulfonates and sulfated ethoxylated alcohol is disclosed which results in improved oil recovery in the presence of high concentrations of polyvalent ions including calcium. Field application of petroleum sulfonate has revealed numerous problems associated with the heterogeneous nature of the oleophilic moieties present, however. Specifically in a paper presented at the Society of Petroleum Engineers, Fall 1972, meeting held in San Antonio, the problem of fractionation of the petroleum sulfonate surfactant was noted. The paper, SPE 4084, is titled "Borregas Surfactant Pilot Test" by Messrs. S. A. Pursley and H. L. Graham. In the paper it is stated that "The higher equivalent weight materials were selectively absorbed on the mineral surfaces of the rock" and "the higher equivalent weight portions of the [petroleum sulfonate] surfactant are the prime contributors to low interfacial tensions that permit mobilization of residual oil." Thus a unique problem is recognized in the use of petroleum sulfonate in that the most effective portion of petroleum sulfonate is selectively removed from aqueous solution by adsorption on the rock surface and/or partitioning into the oil phase.
The Reisberg patent states that a concentration lower limit of one percent surfactant is mandatory. Our surfactant combination may be used very effectively at a much lower concentration.
Nonionic surfactants, such as polyethoxylated alkyl phenols, polyethoxylated aliphatic alcohols, carboxylic esters, carboxylic amides, and polyoxyethylene fatty acid amides, have a somewhat higher tolerance of polyvalent ions such as calcium or magnesium than do the more commonly utilized anionic surfactants. While it is technically feasible to employ a nonionic surfactant solution to decrease the interfacial tension between the injected aqueous displacing medium and petroleum contained in some limestone formations, such use would not be economically feasible for several reasons. Nonionic surfactants are not as effective on a per unit weight basis as are the more commonly used anionic surfactants, and furthermore, the nonionic surfactants have a higher cost per unit weight than do the anionic surfactants. Moreover, polyethoxylated alkyl phenol nonionic surfactants exhibit a reverse solubility relationship with temperature and become insoluble at temperatures in the range of 125.degree.F, making them ineffective in many oil formations. Other types of nonionic surfactants hydrolyze at temperatures above about 165.degree.F.
The use of certain combinations of anionic and nonionic surfactant to combat hard water formations is also taught in the art. For example, U.S. Pat. No. 3,811,505 discloses the use of alkyl or alkylaryl sulfonates or phosphates and polyethoxylated alkyl phenols; U.S. Pat. No. 3,811,504 teaches the use of three component mixture including an alkyl or alkylaryl sulfonate, an alkyl polyethoxy sulfate and a polyethoxylated alkyl phenol; and U.S. Pat. No. 3,811,507 teaches the use of a water soluble salt of a linear alkyl or alkylaryl sulfonate and a polyethoxylated alkyl sulfate.
The pH of the formation water is also a factor which affects the operability of the surfactant flood. The surfactant should be effective at the pH of the formation water.
Other problems encountered in surfactant flooding operations of the type taught in the prior art include susceptibility of the surfactant to bacterial degradation in the formation, and serious scale deposition in the production well through which formation fluids and previously injected aqueous fluids are produced to the surface of the earth.
The use of the phosphate ester surfactant described more fully hereinafter below is taught in U.S. Pat. No. 3,488,289 as a scale inhibitor.
Thus it can be seen that while many surfactants have been proposed for supplemental oil recovery use, there is a substantial, unfulfilled need for a surfactant composition usable in formation water containing calcium and/or magnesium in excess of 500 parts per million in formations hotter than 125.degree.F which are effective over a broad pH range. There is an especially serious need for a surfactant system with the foregoing properties which is additionally resistant to bacterial degradation in the formation.